JP2009516054A - Method for producing a variable synthesis gas composition - Google Patents

Abstract

Disclosed is a process for the production of variable syngas compositions by gasification. Two or more raw syngas streams are generated in a gasification zone (1) having at least two gasifiers (2, 3) and a portion of the raw syngas is passed to a common water gas shift reaction zone (20). And producing at least one shifted syngas (23) rich in hydrogen and at least one non-shifted syngas stream (10). The shifted syngas stream and unshifted syngas stream (10, 23) are mixed at various ratios downstream of the water gas shift zone, and the mixed syngas stream (25) and unmixed syngas stream (26) are mixed hourly. At a volume and / or composition that can vary depending on the requirements of at least one downstream synthesis gas. The process is useful for supplying synthesis gas from multiple gasifiers for variable co-production of electricity and chemicals during periods of peak and off-peak power demand.
[Selection] Figure 1

Description

BACKGROUND OF THE INVENTION The high prices and declining supply of natural gas and oil have been a factor in the chemical and power industries exploring alternative raw materials for chemical production and electricity generation. On the other hand, coal and other solid carbonaceous fuels, such as petroleum coke, biomass, paper pulping waste, etc. are very abundant and relatively inexpensive, and are reasonable for the field to investigate as an alternative raw material source. It is a good material. Coal and other solid carbonaceous materials can be gasified, that is, partially burned with oxygen to produce a synthesis gas (hereinafter also referred to as “syngas”) that can be cleaned. And can be used to produce a variety of chemicals, or burned to generate electrical power. The gasification process typically involves synthesis gas having a molar ratio of H ₂ to CO of about 0.4 / 1 to 1.2 / 1 with smaller volumes of CO ₂ , H ₂ S, methane and other Produced with inerts.

However, different applications require different H ₂ / CO ratios in order to efficiently utilize the synthesis gas feedstock. For example, the stoichiometry of the Fischer-Tropsch and methanol reaction requires a 2/1 molar ratio of H ₂ / CO, production of synthetic natural gas requires 3/1, and synthesis of acetic acid requires 1/1 And the synthesis gas for the production of ammonia or hydrogen requires only hydrogen. This ratio can be adjusted by means known in the art, for example, through a water gas shift reaction in which carbon monoxide reacts with water to produce hydrogen and carbon dioxide. However, this approach is not satisfactory when there are multiple different downstream requirements for the synthesis gas. For example, when designing an integrated process to produce synthesis gas with varying H ₂ / CO ratio requirements, such as found in chemical and power co-generation facilities, all synthesis gas is gasified One approach is to shift the zone from where the required H ₂ / CO ratio is highest, ie overshifting several fractions of gas. However, the overshift approach affects the energy loss for these processes that do not require syngas with a high molar ratio of hydrogen to carbon. This is because the water gas shift reaction is an exothermic reaction, and during the shift reaction, part of the chemical energy in the synthesis gas (equivalent to the reaction enthalpy of the water gas shift reaction) is converted into thermal energy. Thus, power generation is maximized through the use of non-shifted gas. For example, shifting to a 2/1 H ₂ / CO molar ratio can result in a loss of about 3-12% of chemical energy compared to a non-shifted gas. The amount of loss depends on the initial H ₂ / CO molar ratio of the synthesis gas. Thus, in terms of moles relative to moles, the shift gas has a lower amount of energy than the non-shift gas.

  An integrated gasification combined cycle (abbreviated herein as “IGCC”) power plant typically consists of a fuel (usually coal or petroleum coke) gasification block and a combined cycle power block. The combined cycle and power blocks are essentially the same as those used with natural gas fuel. However, the generation and utilization of syngas from the gasification process is significantly more complicated than drawing fuel from a natural gas pipeline. The solid grinding and preparation, gasification, ash treatment, gas cooling, and sulfur removal steps associated with IGCC require significant capital and are difficult and expensive to frequently shut down and start up. The IGCC power plant is designed to operate continuously with limited turndown capacity, and in essence favors substantially continuous base load operation. Even if the gasification block can be shut down as easily as pipelined natural gas, the idling of the gasifier block will take advantage of power generation and prevent economic penalties. . Thus, there is a disparity between the variable power generation capability of the combined cycle block and the required base load operation of the gasification block. IGCC units are considered in the art as base load units (meaning they do not have the ability to deliver to intermediate load elements). In many power markets, the price of power can fluctuate by two or more factors, such as between peak power demand periods and low power demand periods, for example, between night and daytime. Dependence on base load operation may severely limit the economic feasibility of power generation via IGCC. In fact, the most economical solution would be to generate no power during the off-peak period. Thus, there is a need for an IGCC process that can produce products that are more valuable than electricity from synthesis gas available during off-peak power hours.

  Potential benefits of co-generation of chemicals and electricity are described in, for example, “Clean Coal Technology: Production of Power, Fuels, and Chemicals”, Topical Report 21, September, 2001, U.S. Pat. S. Has been well discussed and discussed in Department of Energy, and Gray and Tomlinson, “Production: A Green Coal Technology”, Mitretech Technical Report MP 2001-28, March, 2001. Many variations have been proposed in the prior art to address the problem of co-generation of chemicals and electricity. A common approach is to operate the gasification block with an essentially constant base load capacity factor. Thus, the generated crude synthesis gas is cleaned to remove most of the sulfur compounds and other impurities, and then the cleaned synthesis gas is so-called partial conversion “once-through” (no gas recycling) chemistry Although supplied to the synthesis reaction, unconverted synthesis gas is burned directly for base load power generation. The synthesized chemicals are stored and used later as fuel for the gas turbine-steam turbine combined cycle during peak demand periods or sold in excess. Co-generated chemicals exemplified in the art are ammonia, methanol, dimethyl ether, and Fischer-Tropsch hydrocarbons.

  Examples of such partial conversion processes involving chemical co-generation are described, for example, in US Pat. No. 4,566,267 for ammonia co-generation, US Pat. No. 5,392,594 for methanol, US Pat. No. 3,986,349 and 4,092,825 describe Fischer-Tropsch hydrocarbons and US Pat. No. 4,341,069 describes dimethyl ether co-production. For further discussion of co-generation of chemicals and power, see, for example, Weber et al., “Methanol Production: Strategies for Effective Use of IGCC Power Plants,” Proceedings of the American Power, 1988. 288-93. However, “through-flow” chemical processes allow the production of relatively small amounts of chemicals. For example, “through-flow” methanol processes typically utilize about 12-30% of the carbon monoxide / hydrogen feed gas, thereby not using the available syngas feedstock efficiently. The amount of chemical product that can be co-produced is limited and significant base load power operation is still required. Furthermore, such “flow through” processes lack the economies of scale for chemical production and often result in high resource costs.

The use of non-shifted synthesis gas for chemical synthesis often severely limits the maximum chemical production that can be achieved. For example, the synthesis of methanol, dimethyl ether and Fischer-Tropsch hydrocarbons consumes 2 moles of H ₂ for every mole of CO, and even if the H ₂ conversion is complete, this stoichiometric requirement is an unshifted synthesis. It is readily apparent that it will limit the conversion of the gas flow. Since only a limited percentage of the available hydrogen, typically about 50%, is converted in the once-through synthesis mode, the process is limited to converting only about 25% of the available synthesis gas to chemical products. Become. Chemical equilibrium and chemical kinetic limitations further limit the potentially feasible transformations with the composition, temperature and pressure at which the reaction is actually carried out.

  In addition to the above deficiencies, the above-described methods and processes in the art include downstream synthesis gas requirements such as co-generation of chemicals and power, etc. (where the synthesis gas volume and / or composition required for each element Does not adequately address the problem of producing multiple syngas compositions. Due to stoichiometric limitations of chemical reactions, a concept that relies on co-generation of continuous once-through chemicals and power can always require substantial base-load operation and lead to high resource requirements There is. Due to the co-generation of chemicals and power, energy loss to power generation was minimized, resource costs were reduced, and the highest thermal efficiency of the power cycle was maintained during power generation, but not used Variable to optimize the amount of syngas shifted during the co-production period so that syngas fuel is converted to chemicals with the highest stoichiometric and resource efficiency in chemical production There is a need for a power generation method. Finally, there is a need for a method for minimizing the shift reactor volume required for co-production concepts with multiple gasifier configurations.

SUMMARY OF THE INVENTION Two or more gasifiers are used to feed raw syngas to a central water gas shift zone to shift a portion of the raw syngas and meet one or more downstream syngas requirements. We have found that by mixing the shift gas stream and the non-shift gas stream downstream of the water gas shift zone at an appropriate ratio, multiple synthesis gas streams having a time-varying composition and volume can be efficiently generated. Accordingly, the present invention is a method for producing a variable synthesis gas composition comprising:
(A) reacting an oxidant stream with a carbonaceous material in a gasification zone comprising at least two gasifiers to produce at least two raw syngas streams comprising carbon monoxide, hydrogen, carbon dioxide and a sulfur-containing compound; Generating;
(B) passing at least one portion of the raw syngas stream obtained in step (a) through a common water gas shift reaction zone to at least one shift-rich syngas stream (i) rich in hydrogen and the raw Generating at least one non-shifted syngas stream (ii) comprising the remainder of the syngas stream; and (c) mixing the shifted syngas stream (i) with a portion of the non-shifted syngas stream (ii). Generating at least one mixed synthesis gas stream (iii) and at least one unmixed synthesis gas stream (iv) comprising the remainder of the non-shifted synthesis gas stream (ii), wherein the mixed synthesis gas stream is at least one A method is provided that includes producing with a volume and / or composition that varies depending on the requirements of the downstream syngas.

  The present invention provides at least two gasifiers connected to a common or shared water gas shift reaction zone, wherein a portion of the raw synthesis gas obtained in these gasifiers is at least one shift synthesis rich in hydrogen. A gas stream and one that can be led to the generation of at least one non-shifted gas stream comprising the remainder of the raw syngas stream are provided. Another aspect of the invention is to mix the shifted synthesis gas stream with all or part of the non-shifted synthesis gas stream downstream of the gasification zone and the water gas shift reaction zone to produce a mixed or unmixed synthesis gas stream. It is to be. The surplus gas cooling zone and the acid gas removal zone are syngas headers downstream of the gasification zone and the water gas shift reaction zone where the variable and shiftable composition shifts of the variable composition with a series size capable of maximum scale. It is provided so that it can be supplied to the zone through the system. The composition of these syngas streams may vary from time to time according to at least one downstream syngas requirement, such as at least one chemical process raw material requirement, at least one power plant fuel requirement, or combinations thereof. it can.

In one embodiment of the invention, for example, a mixed synthesis gas stream can pass through a methanol or dimethyl ether production zone and an unmixed synthesis gas stream can generate electricity through a power generation zone. From the water gas shift reaction zone, steam can be formed by heat recovery from the shift syngas stream, and a portion of the steam can be combined with the raw syngas to provide a wet syngas for the water gas shift reaction. Thus, the present invention also provides a process for producing a variable synthesis gas composition, the process comprising:
(A) reacting an oxidant stream with coal or petroleum coke in a gasification zone comprising at least two gasifiers to produce at least two raw materials comprising carbon monoxide, hydrogen, carbon dioxide and a sulfur-containing compound; Generating a synthesis gas stream;
(B) passing at least a portion of the raw syngas stream obtained in step (a) through a common water gas shift reaction zone so that the molar ratio of hydrogen to carbon monoxide is from 1: 1 to 20: 1 Producing one shifted syngas stream (i) and at least one non-shifted syngas stream (ii) comprising the remainder of the raw syngas stream;
(C) generating steam within the water gas shift reaction zone by recovery of heat from the shifted synthesis gas stream (i);
(D) combining a portion of the steam obtained in step (c) with a portion of the one or more raw syngas streams before passing through the water gas shift reaction zone;
(E) mixing the shifted syngas stream (i) and a portion of the non-shifted syngas stream (ii) to obtain at least one mixed syngas stream (iii) and the remainder of the non-shifted syngas stream (ii). Generating at least one unmixed synthesis gas stream (iv) comprising; and (f) passing the mixed gas stream (iii) through a methanol or dimethyl ether production zone and passing the unmixed gas stream (iv) into a power generation zone. Including threading.

Mixed and unmixed syngas streams can be passed through the methanol and power generation zones and can be produced in volumes that vary depending on peak and off-peak power demands. Thus, another aspect of our invention is a process for producing variable amounts of power and methanol, the process comprising:
(A) reacting an oxidant stream with coal or petroleum coke in a gasification zone comprising at least two gasifiers to produce at least two raw syngas streams comprising carbon monoxide, hydrogen, carbon dioxide and a sulfur-containing compound; Generating;
(B) Passing at least one portion of the raw syngas stream obtained in step (a) through a common water gas shift reaction zone to at least one shifted syngas stream (i) rich in hydrogen and the raw syngas Generating at least one non-shifted syngas stream (ii) comprising the remainder of the stream;
(C) mixing the shift synthesis gas stream (i) and not more than 100 volume percent of the non-shift synthesis gas stream (ii) to produce at least one mixed synthesis gas stream (iii) and non-shifted synthesis gas stream (ii); Generating the remainder;
(D) producing methanol by passing the mixed gas stream (iii) obtained in step (c) through the methanol production zone; and (e) passing the remainder of the unshifted synthesis gas stream (ii) through the power production zone. Generating mixed electricity; the mixed synthesis gas stream is generated in a volume that varies depending on periods of peak and off-peak power demand in the power generation zone. Syngas is consumed in the methanol production zone and in the power generation zone where the demand for synthesis gas fluctuates in a periodic and substantially out of phase. In one aspect, for example during off-peak power demand periods, no more than 100 percent of the non-shifted syngas is mixed with the shifted syngas to produce at least one mixed syngas that is used to produce methanol. Alternatively, the raw syngas does not shift much during periods of peak power demand and can be directed to a power plant to generate electricity.

BRIEF DESCRIPTION OF THE DRAWINGS FIG. 1 shows a schematic flow diagram for one embodiment for producing variable composition and volume of synthesis gas.

DETAILED DESCRIPTION The present invention provides at least two gasifiers connected to a common or shared water gas shift reaction zone. Here, a portion of the raw syngas from these gasifiers is introduced to produce at least one shifted syngas stream rich in hydrogen and at least one non-shifted gas stream comprising the remainder of the raw syngas stream. it can. The remainder of the shift synthesis gas and the non-shift synthesis gas can be mixed downstream of the water gas shift reaction zone to produce a mixed synthesis gas stream and an unmixed synthesis gas stream. Thus, in a general aspect, the present invention provides a process for producing a variable synthesis gas composition, the process comprising:
(A) reacting an oxidant stream with a carbonaceous material in a gasification zone comprising at least two gasifiers to produce at least two raw syngas streams comprising carbon monoxide, hydrogen, carbon dioxide and a sulfur-containing compound; Generating;
(B) passing at least a portion of at least one of the raw syngas streams obtained in step (a) through a common water gas shift reaction zone to at least one shifted syngas stream rich in hydrogen (i), and Generating at least one non-shifted syngas stream (ii) comprising the remainder of the syngas stream; and (c) the shifted syngas stream (i) and a portion of the non-shifted syngas stream (ii); To produce at least one mixed synthesis gas stream (iii) and at least one unmixed synthesis gas stream (iv) comprising the remainder of the unshifted synthesis gas stream (ii);
And generating the mixed synthesis gas stream with a volume and / or composition that varies depending on the requirements of at least one downstream synthesis gas. The volume and composition of the mixed and unmixed syngas streams can be varied from time to time to meet one or more downstream syngas requirements, such as raw material requirements for methanol plants, fuels for power plants or these Can be satisfied. In accordance with our invention, the carbonaceous material and oxygen can be continuously reacted in one or more gasifiers to produce synthesis gas at a substantially constant rate. As used herein, the term “substantially constant rate” is understood to mean that gas is continuously provided in an uninterrupted manner and at a constant level. However, “substantially constant speed” is not intended to exclude normal interruptions that may occur, for example, due to maintenance, activation, or scheduled shutdown periods. For the purposes of the present invention, the terms “sulfur” and “sulfur-containing compound” are synonymous and mean any sulfur-containing compound that is organic or inorganic in nature. Examples of such sulfur-containing compounds are exemplified by hydrogen sulfide, sulfur dioxide, sulfur trioxide, sulfuric acid, elemental sulfur, carbonyl sulfide, mercaptans, and the like. The syngas of the present invention containing carbon dioxide, carbon monoxide and hydrogen can be produced in any number of ways known in the art, such as steaming carbonaceous materials such as natural gas or petroleum derivatives or reforming carbon dioxide. Can be provided by, but by partial oxidation or gasification of carbonaceous materials such as petroleum residues, bitumen, subbituminous and anthracite and coke, lignite, oil shale, oil sand, peat, biomass, petroleum refinery residue or coke, etc. Preferably obtained.

Unless stated otherwise, the numerical parameters set forth in the following description and appended claims are approximations that may vary depending on the desired properties sought to be obtained by the present invention. At a minimum, each numeric parameter should be interpreted by applying conventional rounding techniques, at least in terms of the number of significant digits recorded. Further, the ranges stated in this disclosure and the claims are intended to specifically include the entire range, not just one or more endpoints. For example, ranges described as 0 to 10 are all integers between 0 and 10, such as 1, 2, 3, 4, etc., all fractions between 0 and 10, such as 1.5, 2.3. , 4.57, 6.113, etc., and endpoints 0 and 10 are intended to be disclosed. Also, ranges relating to chemical substituents, such as “C ₁ to C ₅ hydrocarbons” specifically include and disclose C ₁ and C ₅ hydrocarbons and C ₂ , C ₃ and C ₄ hydrocarbons. Is intended to be.

  Regardless of whether the numerical ranges and parameters describing the broad scope of the present invention are approximate values, the numerical values described in the specific examples are recorded as precisely as possible. Any numerical value, however, inherently contains certain inevitable predetermined errors resulting from the standard deviation found in their respective testing measurements.

  As used in the detailed description and the appended claims, the singular forms “a”, “an”, and “the” include these plural referents unless the context clearly dictates otherwise. For example, reference to a “syngas stream” or a “gasifier” is intended to encompass one or more synthesis gas streams or gasifiers. References to compositions or processes that contain or include "an" ingredient or "a" step include other ingredients or other steps in addition to the named one, respectively. Intended.

  “comprising” or “containing” or “including” means that at least the named compound, element, particle or method step or the like is present in the composition or article or method. We mean. However, the existence of other compounds, catalysts, materials, particles, method steps, etc. is claimed even if other such compounds, materials, particles, method steps, etc. have the same function as the named ones. It is not excluded unless explicitly excluded in the scope of.

  It is also not intended that the reference to one or more method steps does not exclude the presence of additional method steps before or after the listed steps of the combination or between those explicitly defined steps. Should be understood. In addition, process step or ingredient letters are a convenient means for defining individual activities or ingredients, and the listed letters can be arranged in any order, unless otherwise specified.

  The process of the present invention involves reacting an oxidant stream with a carbonaceous material in a gasification zone that includes at least two gasifiers to produce at least two raw syntheses that include carbon monoxide, hydrogen, carbon dioxide, and a sulfur-containing compound. Generating a gas stream. Typically, two or more gasifiers are sized to provide at least 90% of the maximum capacity fuel requirement of the power generation zone. Any one of several known gasification processes can be incorporated into the method of the present invention. These gasification processes generally fall within the broad category presented in Chapter 5 of “Gasfication”, (C. Higman and M. van der Burgt, Elsevier, 2003). Examples include moving bed gasifiers such as Lurgi dry ashing process, British Gas / Lurgi slagging gasifier, Ruhr 100 gasifier, etc .; fluidized bed gasifiers such as Winkler and high temperature Winkler processes, Kellogg Brown and Root ( KBR) transfer gasifier, Lurgi circulating fluidized bed gasifier, U-Gas agglomerating fluid bed process, and Kellogg Rust Westinghouse mass fluidized bed process; and jet gasifiers such as Texaco, Shell, Prenflo Noell, E-Gas (or Destec), CCP, Eagle, and Koppers-Totzek processes. Gasifiers contemplated for use in the process range from 21 to 103, ranging from 1 to 103 absolute bar (abbreviated herein as “bara”) and pressures and temperatures between 400 ° C. and 2000 ° C. It can be operated at 83 bara and preferred values in the temperature range between 500 ° C and 1500 ° C. Depending on the carbonaceous or hydrocarbonaceous raw material used therein and the type of gasifier utilized to generate gaseous carbon monoxide, carbon dioxide and hydrogen, the raw material preparation may be ground and ground One or more unit operations of drying, slurrying, and drying the prepared raw materials in a suitable fluid (eg, water, organic liquid, supercritical or liquid carbon dioxide) can be included. Typical carbonaceous materials that can be oxidized to produce synthesis gas include, but are not limited to, petroleum residues, bitumen, sub-bituminous, and anthracite and coke, lignite, oil shale, oil sand, peat, biomass , Petroleum refining residue, petroleum coke and the like.

  The oxidant stream can comprise pure molecular oxygen or other suitable gaseous stream containing a substantial amount of molecular oxygen and is charged to the gasifier along with the carbonaceous or hydrocarbonaceous raw material. The oxidant stream can be prepared by any method known in the art, such as cryogenic distillation of air, pressure swing adsorption, membrane separation, or any combination thereof. The purity of the oxidant stream is typically at least 85% by volume of oxygen; for example, the oxidant stream can comprise at least 95% by volume of oxygen, or in other examples at least 98% by volume of oxygen.

  The oxidant stream and the prepared carbonaceous or hydrocarbonaceous raw material are introduced into at least two gasifiers, where the oxidant is consumed and the raw materials are carbon monoxide, hydrogen, carbon dioxide, water and various It is substantially converted into at least two synthesis gas (syngas) streams containing impurities (such as sulfur-containing compounds). Examples of impurities that the raw syngas stream may contain include hydrogen sulfide, carbonyl sulfide, methane, ammonia, hydrogen cyanide, hydrogen chloride, mercury, arsenic, and other metals, depending on the origin of the raw materials and the type of gasifier Is mentioned. In addition to at least two gasifiers, the gasification zone can include a hot gas cooling facility, an ash / slag treatment facility, a gas filter, and a scrubber. The precise manner in which the oxidant and raw materials are introduced into the gasifier is within the skill of the art; however, typically the gasifier will operate continuously and at a substantially constant rate. Become.

  A water gas shift reaction can be employed to change the molar ratio of syngas to hydrogen monoxide and provide the correct stoichiometry of hydrogen and carbon monoxide for chemical production. Thus, the process of the present invention involves passing at least one of the raw syngas streams from the gasification zone through a common water gas shift reaction zone to at least one shifted syngas stream (i) rich in hydrogen and the raw synthesis Generating at least one non-shifted syngas stream (ii) comprising the remainder of the gas stream. As used herein with respect to raw synthesis gas, the term “part” refers to a portion or fraction of a single raw synthesis gas stream, a portion of two or more raw synthesis gas streams, or a central gas header or manifold, for example. Is understood to mean a portion of the total raw syngas product from the gasification zone, such as after mixing or combining multiple raw syngas streams. For example, based on the total volume of the synthesis gas stream, one or more 1 to 100 volume percent of the raw synthesis gas stream can be directed to a common water gas shift reaction zone. In another example, multiple raw syngas streams from the gasification zone can be combined in a central gas header or manifold, and from one of the combined streams on a combined volume basis. 90% by volume can be passed through a common water gas shift reaction zone. As used herein, the term “common” refers to the fact that each gasifier has a separate water gas shift zone to process its syngas product, whereas the water gas shift reaction zone has at least two gasifications. More than one water gas shift reaction zone may be present, intended to mean connected and shared by the device. Thus, in one aspect of the invention, our process can include multiple water gas shift reaction zones, and at least one of the water gas shift reaction zones is connected and shared by at least two gasifiers.

  At least one portion of the raw syngas stream is directed to a common water gas shift reaction zone where the syn gas undergoes an equilibrium limit water gas shift reaction, where carbon monoxide reacts with water to produce hydrogen and carbon dioxide. .

CO + H ₂ O ← → CO ₂ + H ₂
Typically, the water gas shift reaction is accomplished by methods known in the art in a catalytic manner. Advantageously, the water gas shift catalyst is sulfur resistant. For example, such sulfur-resistant catalysts include, but are not limited to, cobalt-molybdenum catalysts. The operating temperature is typically from 250 ° C to 500 ° C.

  The water gas shift reaction can be accomplished in any reactor format known in the art for controlling the heat release of the exothermic reaction. Examples of suitable reactor types are single stage adiabatic fixed bed reactors; multistage adiabatic fixed bed reactors with interstage cooling, steam generation or cold-shotting; tubular fixation with steam generation or cooling A bed reactor; and a fluidized bed. Typically, about 80-90% of the carbon monoxide will be converted to carbon dioxide and hydrogen due to equilibrium limits in a single stage adiabatic reactor. If more conversion is required (ie for hydrogen production), an additional stage with a lower outlet gas temperature can be used.

  Due to the highly exothermic nature of the water gas shift reaction, heat from the shift synthesis gas stream (i) is mixed with the non-shift synthesis gas stream (ii) as it exits the water gas shift reaction zone. By collecting before the steam, steam can be generated in the water gas shift reaction zone. The steam generated in the water gas shift reaction zone can be led to a common steam header and used as a general practical steam. However, the raw syngas produced by gasification often does not contain enough water to carry out the water gas shift reaction to the desired conversion. Alternatively, a portion of the steam is combined with a portion of one or more raw syngas streams from the gasification zone to produce at least one wet syngas stream, and the wet syngas stream is converted to a water gas shift reaction. By passing through the zone, steam generated within the water gas shift reaction zone can be used to add enough water to the raw syngas entering the water gas shift reaction zone. Typically, the molar ratio of water to carbon monoxide in the wet synthesis gas stream is 1.5: 1 to 3: 1. Further examples of water: carbon monoxide molar ratios that can be produced are 2: 1 and 2.5: 1.

  Mixing the shifted syngas stream (i) with a portion of the non-shifted syngas stream (ii), comprising at least one mixed syngas stream (iii), and the remainder of the non-shifted syngas stream (ii) One unmixed synthesis gas stream (iv) can be generated. For our invention, the volume and composition of the mixed and unmixed synthesis gas streams, (iii) and (iv), respectively, is the portion of the raw synthesis gas that is directed to the water gas shift reaction zone, the CO in the water gas shift reaction zone And one or more parameters such as the portion of the non-shifted syngas stream (ii) mixed with the shifted syngas stream (i) can be easily and quickly adjusted. Mixing of the shift and non-shift gas streams can be accomplished by any means known to those skilled in the art, such as by passing the combined gas stream through a static mixer. The volume of the mixed synthesis gas stream and the non-mixed synthesis gas stream, respectively (iii) and (iv), and / or the composition of the mixed synthesis gas stream (iii) is at least one downstream requirement, e.g., at least 1 It can vary depending on the raw material requirements of one chemical process, the fuel requirements of at least one power plant, a combination thereof, or the like. For example, a mixed synthesis gas stream (iii) and an unmixed synthesis gas stream (iv) can be produced with volumes that vary periodically depending on the requirements of at least one downstream synthesis gas. As used herein, the term “periodically” is understood to have its generally accepted meaning “related to or occurring in a time interval or period”. The period or time interval may occur regularly or irregularly, such as once every 24 hours.

  In one aspect, for example, the process of the present invention further comprises passing a mixed synthesis gas stream (iii) through a chemical production zone and passing an unmixed synthesis gas stream (iv) through a power generation zone, which are simultaneous. Or it can be operated in a cyclic and substantially out of phase. The power generation zone is a means for converting chemical and kinetic energy in the syngas feed to electrical or mechanical energy, typically at least one turbo expander (hereinafter also referred to as “combustion turbine”). ) Shape. Typically, the power generation zone will include a combined circulation system as the most efficient way to convert the energy in the syngas to electrical energy, the Braton and Carnot cycles for power generation. including. In combined circulating operation, gaseous fuel is combined with an oxygen-containing gas, burned, and fed to one or more combustion turbines to generate electrical or mechanical energy. Hot exhaust gas from one or more combustion turbines is fed to one or more heat recovery steam generators (HRSG), where a fraction of the thermal energy in the hot exhaust gas is recovered as steam. . In a turbine where steam from one or more HRSGs and any steam generated in other sections of the process (ie, due to recovery of the exothermic chemical reaction) is fed to one or more steam turboexpanders and discharged to the condensing means Generate electrical or mechanical energy before eliminating any remaining low level heat. Many variations in basic combined circulation operation are known in the art. Examples are the HAT (wet air turbine) cycle and the Tophat cycle. All are suitable for unlimited use within the power generation zone of the present invention. For example, in another aspect of the present invention, the power generation zone can include an integrated gasification combined cycle (abbreviated herein as “IGCC”) power plant.

  In another aspect of the invention, mixed and unmixed syngas streams can be generated with volumes that vary depending on the peak and off-peak power demands of the power generation zone. For example, one or more of the combustion turbines that produce electricity can be shut down during periods of off-peak power demand. By shutting down the combustion turbine, the portion of the raw syngas obtained in step (a) consumed by the combustion turbine is instead sent to the water gas shift reaction zone to increase the volume of the shifted syngas stream (i ) And mixed synthesis gas stream (iii) and less non-shifted synthesis gas stream (ii) and unmixed synthesis gas stream (iv). A portion of the non-shifted syngas stream (ii) is mixed with the shifted syngas stream (ii) to have at least one mixed syngas having a suitable hydrogen: carbon monoxide molar ratio to the chemical production zone. A stream (iii) is generated. For example, a hydrogen: carbon monoxide molar ratio of about 2: 1 is necessary for methanol production. The mixed synthesis gas stream (iii) is then directed to the chemical production zone. However, during periods of peak power demand, this procedure is reversed and reduces the volume of raw synthesis gas that is directed to a common water gas shift reaction zone and produces a larger volume of unmixed synthesis gas (iv). And send it to the combustion turbine. In this manner, the synthesis gas throughput is substantially maintained at the base load value, making full use of expensive synthesis gas generation equipment, while delivering cyclic and variable power load elements that are not required for power generation. Maximizing chemical production using complex synthesis gas. Such novel combinations provide significant flexibility in power generation operation, provide substantial economic benefits, and are particularly responsive to the current power fluctuation demands faced by electrical producers. This is in direct contrast to conventional IGCC power plant designs where the power plant is operated in a base load mode with uneconomic load following capability. For example, in one aspect of the invention, a power plant can operate at 100% of its maximum power generation capacity at daytime peak power demand and can be fully fueled by syngas.

  “Peak power demand” as used herein within the context of the present invention means the maximum power demand of the power generation zone within a predetermined 24 hour period. As used herein, the phrase “period of peak power demand” means one or more intervals of time within the 24-hour period, where the power demand in the power generation zone is at least 90% of the maximum power demand. As used herein, “period of off-peak power demand” refers to one or more intervals of time within a predetermined 24-hour period in which the power demand in the power generation zone is less than 90% of the peak power demand defined above. Means.

  The chemical production zone is any chemical that can be efficiently obtained from synthesis gas feedstock, such as methanol, alkyl formate, oxoaldehyde, ammonia, dimethyl ether, hydrogen, Fischer-Tropsch product, methane, or these Can be used to produce a combination of one or more of these chemicals. For example, in one embodiment of the invention, the chemical production zone is a methanol production zone.

  The methanol production zone can include any type of methanol synthesis plant known to those skilled in the art, and many of these are widely practiced on a commercial basis. Most commercial methanol synthesis plants operate in the gas phase with a pressure range of 25 to 140 bara and various copper based catalyst systems depending on the technology used. A number of different state-of-the-art techniques for synthesizing methanol are known, such as the ICI (Imperial Chemical Industries) process, the Lurgi process, the Haldor-Topoe process, and the Mitsubishi process. Liquid phase processes are also well known in the art. Thus, the methanol process according to the present invention can include a fixed bed or liquid slurry phase methanol reactor.

  The synthesis gas stream is typically fed to the methanol reactor at a pressure of 25 to 140 bara, depending on the process employed. The synthesis gas then reacts on the catalyst to form methanol. The reaction is exothermic; therefore, heat removal is usually necessary. The raw or impure methanol can then be condensed and purified to remove impurities such as higher alcohols such as ethanol and propanol, or burned as fuel without purification. The uncondensed vapor phase containing unreacted synthesis gas feedstock is typically recycled to the methanol process feed.

  Switching between power generation and chemical production is another consideration of the present invention. For example, the flow to the methanol reactor can be significantly reduced or stopped when producing methanol by gas phase reaction and during periods when there is no methanol production. The reactor can be closed with a valve and the gaseous component can be contained in the reactor so that the reactive synthesis gas component quickly reaches the equilibrium limit for methanol production. The reactor can be maintained in this idle state indefinitely. However, it is preferred to maintain the reactor temperature above, for example, 200 ° C. so that methanol production immediately begins open reintroduction of the synthesis gas stream. Surprisingly, it has been found that the thermal mass of the catalyst and the reactor itself will maintain the temperature above the desired range for several hours, typically 4 to 10 hours, without further heating. However, it may be necessary to provide additional heat injection into the reactor that has been idled. Depending on the reactor type used in the present invention, the additional heat can be circulated through a hot inert gas (eg, nitrogen) through the reactor, or a heat transfer medium (eg, hot water or steam) through the heat transfer surface of the reactor. For example by contacting a tube wall of a fixed bed tubular reactor.

  For liquid phase slurry reactors, it is advantageous to maintain the catalyst suspended in the liquid when the methanol reactor is in idle mode, i.e. during periods of peak power demand. An inert gas, such as nitrogen, is fed to the reactor in place of the reactive synthesis gas at a rate and volume that prevents catalyst settling. Methods for calculating the flow rate required to ensure catalyst suspension are well known in the art. When methanol production is to resume, synthesis gas begins to flow as the nitrogen flow is reduced. The purge from the reactor, which can be increased initially, is reduced to a normal level as the amount of nitrogen decreases.

  The thermal mass of the slurry fluid, reaction vessel, and / or catalyst will maintain the temperature above the desired range for several hours, typically 4 to 10 hours, without further heating. However, it may be necessary to provide additional heat injection to the idled reactor. Depending on the reactor type used in the present invention, the additional heat can be circulated through a hot inert gas (eg, nitrogen) through the reactor, or a heat transfer medium (eg, hot water or steam) through the heat transfer surface of the reactor. Can be given by contacting. For example, at least one portion of the syngas stream can be passed through the methanol production zone during periods of peak power demand and the methanol production zone can be maintained at an elevated temperature through the production of a small amount of methanol. All of the methanol product can then be passed from the methanol production zone to the power generation zone as additional fuel during periods of peak power demand.

  One or more separate gas cooling zones are provided for each of the syngas streams (i) and (ii) obtained in step (b) or each of the syngas (iii) and (iv) obtained in step (c). In which the temperature of the synthesis gas is reduced. Gas cooling and recovery of thermal energy from the synthesis gas can be accomplished by any means known in the art. For example, the gas cooling zone may include the following steam generated heat exchangers (ie, boilers) (where heat is transferred from the synthesis gas to boil water); gas-gas alternators; boiler feed water exchangers; forced air It can include at least one of the types of heat exchangers selected from: exchangers; water cooling exchangers; direct contact water exchangers; or a combination of one or more of these heat exchangers. The use of multiple steam generating heat exchangers that can successfully produce lower pressure steam levels is accomplished within the scope of the present invention. The steam and condensate generated in the gas cooling zone can achieve one or more steam products at different pressures. The gas cooling zone can optionally include other absorption, adsorption, or condensation steps for the removal of trace impurities such as ammonia, hydrogen chloride, hydrogen cyanide, and trace metals such as mercury, arsenic, and the like.

  Our new process is a separate process for each of the synthesis gas streams (i) and (ii) obtained in step (b) or each of the synthesis gas streams (iii) and (iv) obtained in step (c). It may further include passing through an acid gas removal zone where acid gases such as hydrogen sulfide or carbon dioxide are removed or their concentrations are reduced. For example, removing sulfur-containing compounds present in the synthesis gas in the acid gas removal zone to prevent poisoning of any catalyst when the gas is used for chemical synthesis, or gas for power generation It is often preferred to reduce the release of sulfur to the environment when used. Thus, in accordance with the present invention, the acid gas removal zone can include a sulfur removal zone that can employ any of a number of methods known in the art for removal of sulfur-containing compounds from a gaseous stream. Sulfur compounds can be recovered from the synthesis gas feed to the sulfur removal zone by chemical absorption methods, illustratively using caustic soda, potassium carbonate or other inorganic bases, or alkanolamines. Examples of suitable alkanolamines for the present invention include primary, secondary and tertiary amino alcohols containing a total of 10 or fewer carbon atoms and having a normal boiling point of less than 250 ° C. Specific examples include primary amino alcohols such as monoethanolamine (MEA), 2-amino-2-methyl-1-propanol (AMP), 1-aminobutan-2-ol, 2-aminobutan-1-ol, 3 -Amino-3-methyl-2-pentanol, 2,3-dimethyl-3-amino-1-butanol, 2-amino-2-ethyl-1-butanol, 2-amino-2-methyl-3-pentanol 2-amino-2-methyl-1-butanol, 2-amino-2-methyl-1-pentanol, 3-amino-3-methyl-1-butanol, 3-amino-3-methyl-2-butanol, 2-amino-2,3-dimethyl-1-butanol, secondary amino alcohols such as diethanolamine (DEA), 2- (ethylamino) ethanol (EAE), -(Methylamino) ethanol (MAE), 2- (propylamino) ethanol, 2- (isopropylamino) ethanol, 2- (butylamino) ethanol, 1- (ethylamino) ethanol, 1- (methylamino) ethanol, Examples include 1- (propylamino) ethanol, 1- (isopropylamino) ethanol, and 1- (butylamino) ethanol, and tertiary amino alcohols such as triethanolamine (TEA) and methyldiethanolamine (MDEA).

  Alternatively, sulfur in the synthesis gas feed to the acid gas removal zone can be removed by physical absorption methods. Examples of suitable physical absorbent solvents are methanol and other alkanols, propylene carbonate and other alkyl carbonates, dimethyl ethers of polyethylene glycols with 2 to 12 glycol units, and mixtures thereof (trade names of Selexol ™ solvents) Generally known), n-methylpyrrolidone, and sulfolane. Physical and chemical absorption methods are combined as illustrated in the Sulfinol ™ process using sulfolane and alkanolamine as an absorbent, or the Amisol ™ process using a mixture of amine and methanol as an absorbent. Can be used.

  The sulfur-containing compound was a solid fixed bed, fluidized bed, or moving bed exemplified by zinc titanate, zinc ferrite, tin oxide, zinc oxide, iron oxide, copper oxide, cerium oxide, or mixtures thereof. It can be recovered from the gaseous feed to the sulfur removal zone by a solid sorption process. If required for chemical synthesis requirements, chemical or physical absorption processes or solid sorption processes can be followed by additional methods for final sulfur removal. Examples of final sulfur removal processes are adsorption on zinc oxide, copper oxide, iron oxide, manganese oxide, and cobalt oxide.

  Typically, at least 90 mole percent, more typically at least 95 mole percent, and even more typical of the total sulfur-containing compounds present in synthesis gas streams (i) and (ii) or (iii) and (iv) Specifically, at least 99 mole percent is removed in the sulfur removal zone. Typically, the synthesis gas used for chemical production requires more severe sulfur removal, i.e., at least 99.5% removal, to prevent deactivation of the chemical synthesis catalyst, more typically The sulfur contained in the exhaust gas from the sulfur removal zone needs to be less than 5 volume 5 ppm.

  Within the acid gas removal zone, in addition to sulfur, some of the carbon dioxide present can also be removed prior to passing the shift synthesis gas stream and mixed synthesis gas stream (i) or (iii) through the chemical production zone. Carbon dioxide removal or reduction can include any of a number of methods known in the art. Carbon dioxide in the gaseous feed can be removed by chemical absorption methods exemplified by using caustic soda, potassium carbonate or other inorganic bases, or alkanolamines. Examples of alkanolamines suitable for the present invention include primary, secondary and tertiary aminoalcohols containing a total of 10 or fewer carbon atoms and having a normal boiling point of less than 250 ° C. Specific examples include primary amino alcohols such as monoethanolamine (MEA), 2-amino-2-methyl-1-propanol (AMP), 1-aminobutan-2-ol, 2-aminobutan-1-ol, 3 -Amino-3-methyl-2-pentanol, 2,3-dimethyl-3-amino-1-butanol, 2-amino-2-ethyl-1-butanol, 2-amino-2-methyl-3-pentanol 2-amino-2-methyl-1-butanol, 2-amino-2-methyl-1-pentanol, 3-amino-3-methyl-1-butanol, 3-amino-3-methyl-2-butanol, 2-amino-2,3-dimethyl-1-butanol, and secondary amino alcohols such as diethanolamine (DEA), 2- (ethylamino) ethanol (E E), 2- (methylamino) ethanol (MAE), 2- (propylamino) ethanol, 2- (isopropylamino) ethanol, 2- (butylamino) ethanol, 1- (ethylamino) ethanol, 1- (methyl Amino) ethanol, 1- (propylamino) ethanol, 1- (isopropylamino) ethanol, and 1- (butylamino) ethanol, and tertiary amino alcohols such as triethanolamine (TEA) and methyldiethanolamine (MDEA) Can be mentioned.

  Alternatively, carbon dioxide in the gaseous feed can be removed by physical absorption methods. Examples of suitable physical absorbent solvents are methanol and other alkanols, propylene carbonate and other alkyl carbonates, dimethyl ethers of polyethylene glycols with 2 to 12 glycol units, and mixtures thereof (trade names of Selexol ™ solvents) Generally known), n-methylpyrrolidone, and sulfolane. Physical and chemical absorption methods are combined as illustrated in the Sulfinol ™ process using sulfolane and alkanolamine as an absorbent, or the Amisol ™ process using a mixture of amine and methanol as an absorbent. Can be used. If required for chemical synthesis requirements, the chemical or physical absorption process can be followed by additional methods for final carbon dioxide removal. An example of a final carbon dioxide removal process is a pressure or temperature swing adsorption process.

  If required for a particular chemical synthesis process, typically at least 60%, more typically at least 80% of the carbon dioxide in the feed gas can be removed in the acid gas removal zone. For example, the process of the present invention removes carbon dioxide from the shift synthesis gas stream or mixed synthesis gas stream (i) or (iii) before passing the synthesis gas through the methanol production zone, It can further include providing a carbon dioxide concentration of 0.5 to 10 mole percent on a total molar basis. In other examples, carbon dioxide can be removed from at least one of the syngas streams (i) or (iii) to a concentration of 2 to 5 mol%. Many sulfur and carbon dioxide removal technologies are capable of removing both sulfur and carbon dioxide. Thus, the sulfur and carbon dioxide removal steps are integrated together so that each of the sulfur and carbon dioxide is selectively (ie, in a substantially separate product stream) or non-selectively (ie, one combination). As a product stream) can be simultaneously removed by means well known in the art.

  In order to reduce the temperature of the crude synthesis gas as required by the particular acid gas removal technique used herein, the gas cooling zone as described above can precede the acid gas removal zone. Thermal energy from the synthesis gas can be recovered via steam generation in the cooling system by means known in the art. The gas cooling zone can optionally include other absorption, adsorption, or condensation steps for removal or reaction of trace impurities such as ammonia, hydrogen chloride, hydrogen cyanide, trace metals such as mercury, arsenic and the like. The gas cooling zone can optionally include a reaction step for converting carbonyl sulfide to hydrogen sulfide and carbon dioxide via reaction with water.

Another aspect of our invention is a process for producing a variable synthesis gas composition, the process comprising:
(A) reacting an oxidant stream with coal or petroleum coke in a gasification zone comprising at least two gasifiers to produce at least two raw syngas streams comprising carbon monoxide, hydrogen, carbon dioxide and a sulfur-containing compound; Generating;
(B) passing at least a portion of the raw syngas stream obtained in step (a) through a common water gas shift reaction zone so that the molar ratio of hydrogen to carbon monoxide is from 1: 1 to 20: 1 Producing one shifted syngas stream (i) and at least one non-shifted syngas stream (ii) comprising the remainder of the raw syngas stream;
(C) generating steam within the water gas shift reaction zone by recovery of heat from the shifted synthesis gas stream (i);
(D) combining a portion of the steam obtained in step (c) with a portion of the one or more raw syngas streams before passing through the water gas shift reaction zone;
(E) mixing the shifted syngas stream (i) and a portion of the non-shifted syngas stream (ii) to obtain at least one mixed syngas stream (iii) and the remainder of the non-shifted syngas stream (ii). Generating at least one unmixed synthesis gas stream (iv) comprising; and (f) passing the mixed gas stream (iii) through a methanol or dimethyl ether production zone and passing the unmixed gas stream (iv) into a power generation zone. Including threading.

  It is understood that the above process includes various aspects of gasifiers, synthesis gas streams, steam generation, oxidant streams, carbonaceous materials, power generation zones, acid-gas removal zones, and gas cooling zones as described above. Is done. For example, the process may include a separate gas for each of the synthesis gas streams (i) and (ii) obtained in step (b) or for each of the synthesis gas streams (iii) and (iv) obtained in step (e). It can further include passing through a cooling zone. Each of the synthesis gas streams (i) and (ii) or (iii) and (iv) may be passed through a separate acid gas removal zone including a sulfur removal zone, a carbon dioxide removal zone, or a combination thereof. The process comprises at least 95 mole percent of the total sulfur-containing compounds present in the synthesis gas streams (i) and (ii) or (iii) and (iv) in the sulfur removal zone and / or one of the carbon dioxide. Further removing the portion from the synthesis gas stream (iii) in the carbon dioxide removal zone.

  The mixed synthesis gas stream can be passed through a chemical production zone that can include either a methanol process or a dimethyl ether process, and the non-mixed gas can be passed through a power generation zone to generate electricity as described above. it can. For example, mixed and unmixed syngas streams (iii) and (iv) can be generated with volumes that vary depending on the peak and off-peak power demands of the power generation zone. In this embodiment, for example, the volume of the mixed synthesis gas stream (iii) increases during the off-peak power demand period and is used to produce methanol or dimethyl ether, while the volume of the unmixed synthesis gas stream (iv) Decrease. Conversely, during periods of peak power demand, the volume of the unmixed syngas stream (iv) increases and is used as fuel for the power generation zone, while the volume of the mixed syngas stream (iii) decreases. .

Our invention also provides a process for producing variable amounts of power and methanol, the process comprising:
(A) reacting an oxidant stream with coal or petroleum coke in a gasification zone comprising at least two gasifiers to produce at least two raw syngas streams comprising carbon monoxide, hydrogen, carbon dioxide and a sulfur-containing compound; Generating;
(B) Passing at least one portion of the raw syngas stream obtained in step (a) through a common water gas shift reaction zone to at least one shifted syngas stream (i) rich in hydrogen and the raw syngas Producing at least one non-shifted syngas stream (ii) comprising the remainder of the stream;
(C) mixing the shift synthesis gas stream (i) and not more than 100 volume percent of the non-shift synthesis gas stream (ii) to produce at least one mixed synthesis gas stream (iii) and non-shifted synthesis gas stream (ii); Generating the remainder;
(D) producing methanol by passing the mixed gas stream (iii) obtained in step (c) through the methanol production zone; and (e) passing the remainder of the unshifted synthesis gas stream (ii) through the power production zone. Generating a mixed synthesis gas stream in an amount that varies depending on periods of power demand in the peak and off-peak power generation zones. As noted above, the process includes various aspects of gasifiers, synthesis gas streams, steam generation, oxidant streams, carbonaceous materials, power generation zones, acid gas removal zones, and cooling zones as described above. For example, the gasifier can be used to oxidize carbonaceous material such as coal or petroleum coke to syngas and can be sized to provide at least 90% of the maximum capacity fuel requirement of the power generation zone. The purity of the oxidant stream is typically at least 85 volume% oxygen and can include at least 95 volume% oxygen, or in other examples at least 98 volume% oxygen. The methanol production zone is as described above and can include, for example, a fixed bed or liquid slurry phase methanol reactor.

  As described above, the water gas shift is achieved by recovering heat from the shifted syngas stream (i) as it exits the water gas shift reaction zone and before mixing with the unshifted syngas stream (ii) in step (c). Steam can be generated in the reaction zone. Steam generated within the water gas shift reaction zone can be directed to a common steam header and used as a general working steam, or one or more in step (b) from part of the steam and gasification zone By combining with a portion of the raw syngas stream to produce at least one wet syngas stream and passing the wet syngas stream through the water gas shift reaction zone, sufficient for the raw syngas entering the water gas shift reaction zone Can be used to add water. Typically, the molar ratio of water to carbon monoxide in the wet synthesis gas stream is 1.5: 1 to 3: 1. Further examples of water: carbon monoxide molar ratios that can be produced are 2: 1 and 2.5: 1.

  Each of the synthesis gas streams present in step (a), (b) or (c) can pass through a separate gas cooling zone and / or a separate acid gas removal zone. The acid gas removal zone can include a sulfur removal zone, a carbon dioxide removal zone, or a combination thereof. For example, at least 95 mole percent of all sulfur-containing compounds present in the synthesis gas stream present in step (a), (b) or (c) are in the sulfur removal zone. In other embodiments, the process removes a portion of the carbon dioxide from the synthesis gas stream (i) or (iii) before passing through the methanol production zone of step (d) to produce the synthesis gas stream (i) or ( iii) can further include providing a carbon dioxide concentration of 0.5 to 10 mole percent, based on the total moles of gas in.

  Adjusting the volume of raw syngas through the water gas shift reaction zone and the volume of non-shifted syngas (ii) mixed with the shifted syngas stream (i) generates power for the mixed syngas stream (iii) It can be generated in an amount that varies depending on the duration of the zone peak and off-peak power demand. Up to 100 volume percent of the non-shifted syngas stream (ii) can be mixed with the shifted syngas stream (ii). For example, 100 volume percent of the non-shifted syngas stream (ii) can be mixed with the shifted syngas stream (i) during periods of off-peak power demand. In this embodiment, instead of passing through the power generation zone, the total volume of the non-shifted synthesis gas stream (ii) can be mixed with the shifted synthesis gas stream (i) to form a mixed synthesis gas stream (iii). A mixed synthesis gas stream is passed through the methanol production zone and used to produce methanol.

  In other examples, the power generation zone can include at least one combustion turbine that can be shut down during periods of off-peak power demand. Depending on the lower power demand of the power generation zone, the volume of the raw syngas directed to the water gas shift reaction zone can be increased and 100% by volume of the non-shifted syngas stream can be mixed with the shifted syngas stream. it can. The mixed synthesis gas stream is then passed through a methanol production zone. There can be more than one period of off-peak power demand within a 24-hour period. Thus, the combustion turbine can be shut down more than once within a predetermined 24 hour period. Instead of operating the turbine in an inefficient or uneconomic regime, the at least one combustion turbine is shut down at these rates during these periods of off-peak power demand, and the thermodynamic and syngas realized at a constant rate. The gasifier can be operated efficiently with maximum economic value.

  For example, a power generation zone that includes two combustion turbines may operate at 90% or more of full capacity. As the demand for power falls, it may be advantageous to close one or more combustion turbines for economic reasons (ie, low cost of power) or for thermodynamic inefficiencies. Thus, rather than continue to operate one of the turbines in an inefficient and / or uneconomical manner in accordance with the process of the present invention, the turbine is shut down and instead the chemical is passed through the synthesis gas feed stream to the chemical production zone Generate. Thus, instead of generating electricity in a turbine that uses a syngas stream and operates at an inefficient utilization rate, a chemistry that can be used, for example, on the market or used to supplement the fuel requirements of a combustion turbine, using syngas. Generate goods. Any efficiently obtained from syngas feedstocks such as methanol, alkylformates, oxoaldehydes, methane, ammonia, dimethyl ether, hydrogen, Fischer-Tropsch products, or combinations of one or more of these chemicals in addition to methanol It is within the scope of the present invention to produce

In one aspect of the invention, for example, ammonia and / or hydrogen can be produced in the chemical production zone. In this example, the water gas shift reaction zone will be operated to maximize hydrogen and carbon dioxide production. Typical conversion of carbon monoxide to hydrogen and carbon dioxide is greater than 95%. The carbon dioxide removal zone can include the conventional absorption or adsorption techniques described above, followed by a final purification step. For example, in pressure swing adsorption, the oxygen content of hydrogen is reduced to less than 2 ppm by volume. Hydrogen can be sold, or by the Haber-Bosch process, LeBlance et al., “Ammonia”, Kirk-Othmer Encyclopedia of Chemical Technology, Volume 2, 3 ^rd Edition, 1978, pp. It can be used to produce ammonia in the chemical production zone by means known in the art, exemplified by those at 494-500.

  In other embodiments of the invention, Fischer-Tropsch products, such as hydrocarbons and alcohols, are exemplified in US Pat. Nos. 5,621,155 and 6,682,711 within the chemical production zone. It can be produced via a Fischer-Tropsch reaction. Typically, the Fischer-Tropsch reaction can be effective in a fixed bed, slurry bed, or fluidized bed reactor. Fischer-Tropsch reaction conditions can include using a reaction temperature between 190 ° C. and 340 ° C., and the actual reaction temperature is largely determined by the reactor configuration. For example, when using a fluidized bed reactor, the reaction temperature is preferably between 300 ° C. and 340 ° C .; when using a fixed bed reactor, the reaction temperature is preferably between 200 ° C. and 250 ° C .; And when using a slurry bed reactor, the reaction temperature is preferably between 190 ° C and 270 ° C.

The inlet syngas pressure to the Fischer-Tropsch reactor can be used between 1 and 50 bar, preferably between 15 and 50 bar. The synthesis gas can have an H ₂ : CO molar ratio of 1.5: 1 to 2.5: 1, preferably 1.8: 1 to 2.2: 1, in the fresh feed. The syngas typically contains no more than 0.1 wppm sulfur. Gas recycling can optionally be employed in the reaction stage, and the ratio of the amount of gas recycled to the amount of unused syngas feed is 1: 1 to 3: 1, preferably 1.5: 1 to 2. It can be between 5: 1. The space velocity can be 1 to 20, preferably 8 to 12, in m ³ (kg of catalyst) ⁻¹ hr ⁻¹ units in the reaction stage.

In the Fischer-Tropsch reaction stage, in principle, iron-based, cobalt-based or iron / cobalt-based Fischer-Tropsch catalysts can be used, but with a high chain growth potential (ie an alpha value of 0.8 or more, preferably 0. 0). Fischer-Tropsch catalysts that work at 9 or more, more preferably 0.925 or more are typical. Reaction conditions are preferably selected to minimize methane and ethane formation. This tends to give a product stream containing mostly wax and heavy products, ie mostly paraffinic C ₂₀ + linear hydrocarbons.

  The iron-based Fischer-Tropsch catalyst can include precipitated or fused iron and / or iron oxide. However, iron and / or iron oxides sintered, cemented or impregnated on a suitable support can also be used. Iron should be reduced to metallic Fe prior to Fischer-Tropsch synthesis. Iron-based catalysts can contain various levels of promoter, and their role is thought to be to change one or more of the final catalyst activity, stability, and selectivity. Typical promoters are those that affect the surface area of reduced iron (“structural promoter”), which includes Mn, Ti, Mg, Cr, Ca, Si, Al, or Cu or These combinations of oxides or metals can be mentioned.

  Products from the Fischer-Tropsch reaction often include gaseous reaction products and liquid reaction products. For example, gaseous reaction products typically include hydrocarbons boiling below 343 ° C. (eg, exhaust gas via middle distillate). The liquid reaction product (condensed fraction) includes hydrocarbons boiling above 343 ° C. (eg, vacuum gas oil via heavy paraffin) and alcohols of various chain lengths.

  The chemical production zone can also be used to produce oxoaldehydes using hydroformylation processes well known in the art. The hydroformylation reaction is typically carried out by contacting an olefin such as ethylene or propylene with carbon monoxide and hydrogen in the presence of a transition metal catalyst to produce linear and branched aldehydes. . Examples of aldehydes that can be produced by hydroformylation include acetaldehyde, butyraldehyde, and isobutyraldehyde.

  In another example, an alkyl formate such as methyl formate is produced in the chemical production zone. Currently, there are several known processes for the synthesis of alkyl formates such as methyl formate from syngas and alkyl alcohol raw materials. In addition to U.S. Pat. No. 3,716,619, these include reacting carbon monoxide and methanol either in the liquid phase or in the gas phase to form methylform at high pressures and temperatures in the presence of an alkali catalyst and sufficient hydrogen. US Pat. No. 3,816,513, which forms a mate and allows the conversion of carbon monoxide to methanol, and a liquid reaction mixture comprising either methanol and an alkali metal or alkaline earth metal methoxide catalyst US Pat. No. 4,216,339 which reacts carbon monoxide with a stream at high temperature and pressure to produce methyl formate. However, in the broadest aspect of the present invention, any efficient commercially available for the formation of alkyl formates from raw materials containing the corresponding alkyl alcohol and a prepared synthesis gas rich in carbon monoxide. Processes that can be performed are within the scope of the present invention. The exact catalyst or catalysts selected and the concentration, contact time, etc. can vary widely as is known to those skilled in the art. Although it is preferred to use the catalysts disclosed in US Pat. No. 4,216,339, a wide variety of other catalysts known to those skilled in the art can also be used.

  A better understanding of one aspect of the present invention is provided with particular reference to the process flow diagram depicted in FIG. In the embodiment described in FIG. 1, a hydrocarbonaceous or carbonaceous material is converted into any type of two or more gasifiers (shown as gasifiers 2 and 3 in FIG. 1) known in the art. Gasification in the containing gasification zone 1 produces crude synthesis gas streams 4 and 5. Syngas streams 4 and 5 flow between lines 6, 7, 8 and 9 and flow control methods known in the art (flow ratios of streams 6 and 8 to 7 and 9 are the product streams 65 and 66 depending on the desired composition and volume). The proportion of gas introduced into lines 8 and 9 can vary from 0 to 100% of the respective flow in lines 4 and 5. Streams 6 and 7 are combined in line 10 to produce a non-shifted gas stream.

  The fraction of gas directed through lines 8 and 9 is passed to a common water gas shift reaction zone 20, where the gas is at an equilibrium limit where carbon monoxide reacts with water to produce hydrogen and carbon dioxide. Undergoes a water gas shift reaction. Steam generated by the heat of the exothermic shift reaction exits the water gas shift zone via line 22. Depending on the amount of raw syngas water from gasification zone 1, water or steam is added directly to streams 8 and 9 via line 21 to provide sufficient water to properly perform the water gas shift reaction. Sometimes it is necessary. Typically, the molar ratio of CO to vaporous water in the combined feed to the water gas shift zone 20 is 1.5 to 1 or more, more preferably 2 to 1 or more. If desired, all or part of the steam added to the shift zone 20 via line 21 is within the shift zone itself, provided that the pressure in line 22 is greater than or equal to the pressure in lines 8 and 9. It can be supplied from what has been generated (ie via line 22).

  Shift gas is conveyed to gas cooling zone 40 via lines 23 and 25. Here the temperature of the gas is reduced and the gas is ready for further purification. Thermal energy from the synthesis gas can be recovered through any means known in the art. The gas cooling zone 40 includes the following types of heat exchangers: steam generated heat exchangers (ie, boilers) (where heat is transferred from the synthesis gas to boil water), gas-gas alternators, boiler feed water exchange. Can include any or all of a water heater, a forced air exchanger, a water cooling exchanger, and a direct contact water exchanger. The use of multiple steam generating heat exchangers that successfully produce lower pressure steam levels is intended to be within the scope of the present invention. Steam and condensate generated in gas cooling zones 30 and 40 exits via lines 31, 32 and 41, 42, respectively. It will be appreciated that line 41 can integrate one or more steam products at different pressures. The gas cooling zone 40 can optionally include other absorption, adsorption or condensation steps for the removal of trace impurities such as ammonia, hydrogen chloride, hydrogen cyanide, and trace metals such as mercury, arsenic and the like. In addition, the gas cooling zone 40 can optionally include a reaction step for converting carbonyl sulfide to hydrogen sulfide and carbon dioxide via reaction with water.

  Non-shifted gas is conveyed to gas cooling zone 30 via lines 10 and 26 where the temperature of the gas is reduced and the gas is prepared for further purification. Thermal energy from the synthesis gas can be recovered through any means known in the art. The gas cooling zone 30 includes the following types of heat exchangers: steam generating heat exchangers (ie, boilers) (where heat is transferred from the synthesis gas to boil water), gas-gas alternators, boiler feed water exchangers. , Any or all of forced air exchangers, water cooling exchangers, and direct contact water exchangers. The use of multiple steam generating heat exchangers that successfully produce lower pressure steam levels is intended to be within the scope of the present invention. Steam and condensate generated in the gas cooling zone 30 exits via lines 31 and 32, respectively. It will be appreciated that line 31 can integrate one or more steam products at different pressures. The gas cooling zone 30 can optionally include other absorption, adsorption or condensation steps for the removal of trace impurities such as ammonia, hydrogen chloride, hydrogen cyanide, and trace metals such as mercury, arsenic and the like. The gas cooling zone 30 can optionally include a reaction step for converting carbonyl sulfide to hydrogen sulfide and carbon dioxide via reaction with water. The cooled non-shifted syngas can be passed through the acid gas removal zone 50 to remove all or part of the sulfur and / or carbon dioxide, or all or part of it with the cooled shifted syngas. The mixed stream can be passed through line 44.

  The cooled shift gas is conveyed to the acid gas removal zone 60 via lines 43 and 45, where all or part of the acid gas components of the crude synthesis gas, such as hydrogen sulfide, carbonyl sulfide, and carbon dioxide, are removed. . Similarly, the cooled shift gas is conveyed via lines 33 and 46 to an acid gas removal zone 60 where the crude synthesis gas acid gas components such as hydrogen sulfide, carbonyl sulfide, and optionally carbon dioxide are removed. Streams 51 and 61 are rich in recovered sulfur-containing species, and optionally, streams 52 and 62 are rich in carbon dioxide.

  Typically, different removal levels of sulfur-containing species and carbon dioxide are required for different synthesis gas applications. For example, environmental regulations on acid gas emissions from power generation plants, along with carbon dioxide levels that are not currently regulated, typically limit the amount of sulfur in the purified synthesis gas to less than 100 parts per million by volume, An amount of sulfur well below 1 part per million and typically less than 5 mole percent of carbon dioxide is required to ensure proper operation and life of the methanol synthesis catalyst. Many other chemical synthesis catalysts, such as Fischer-Tropsch, ammonia, oxo, and methanation catalysts, have similar or more stringent limits on the amount of acid gas than methanol catalysts. Thus, zones 50 and 60 can be designed for various acid gas removal specifications.

  The sulfur-containing species in streams 51 and 61 can be further processed to produce elemental sulfur by any method known in the art, such as the Claus reaction. Alternatively, sulfur can be oxidized and combined with water to produce sulfuric acid by means well known in the art.

  Lines 24, 44 and 64 are provided for mixing the shifted and non-shifted syngas streams. Typically, after the acid gas removal zone, i.e., via line 64, the shifted syngas stream and the unshifted syngas stream are mixed to produce a mixed syngas stream. All or a portion of the unsulfurized synthesis gas can then be used to mix with the shifted synthesis gas stream via line 64 or can be passed to the power generation zone as fuel for the combustion turbine.

FIG. 3 shows a schematic flow diagram for one embodiment for producing a variable composition and volume of synthesis gas.

Claims (18)

A method for producing a variable synthesis gas composition comprising:
(A) reacting an oxidant stream with a carbonaceous material in a gasification zone comprising at least two gasifiers to produce at least two raw syngas streams comprising carbon monoxide, hydrogen, carbon dioxide and a sulfur-containing compound; Generating;
(B) passing at least a portion of at least one of the raw syngas streams obtained in step (a) through a common water gas shift reaction zone to at least one shifted syngas stream rich in hydrogen (i), and Generating at least one non-shifted syngas stream (ii) comprising the remainder of the syngas stream; and (c) the shifted syngas stream (i) and a portion of the non-shifted syngas stream (ii); To produce at least one mixed synthesis gas stream (iii) and at least one unmixed synthesis gas stream (iv) comprising the remainder of the unshifted synthesis gas stream (ii), wherein the mixed synthesis gas stream In a volume and / or composition that varies depending on the requirements of at least one downstream synthesis gas.   Generating at least one steam in the water gas shift reaction zone, combining at least one portion of the steam from the water gas shift reaction zone and the portion in step (b) of one or more raw syngas streams. The method of claim 1, further comprising: generating two wet syngas streams and passing the wet syngas streams through the water gas shift reaction zone.   The method of claim 2, wherein the wet syngas stream has a molar ratio of water to carbon monoxide of 1.5: 1 to 3: 1.   The method of claim 1, wherein the oxidant stream comprises at least 85 vol% oxygen based on the total volume of the oxidant stream.   The method of claim 1, wherein the carbonaceous material is coal or petroleum coke.   Each of the synthesis gas streams (i) and (ii) obtained in step (b) or each of the synthesis gas streams (iii) and (iv) obtained in step (c) is in a separate gas cooling zone or The method of claim 1, further comprising passing through an acid gas removal zone.   The acid gas removal zone comprises a sulfur removal zone that removes at least 95 mole percent of the total sulfur-containing compounds present in the synthesis gas stream (i) and (ii) or (iii) and (iv). Item 7. The method according to Item 6.   8. The method of claim 7, wherein the downstream syngas requirement comprises at least one chemical process raw material requirement, at least one power plant fuel requirement, or a combination thereof.   (D) passing said mixed synthesis gas stream (iii) through a chemical production zone producing methanol, alkylformate, dimethyl ether, oxoaldehyde, ammonia, methane, hydrogen, Fischer-Tropsch products or combinations thereof; and The method of claim 1, further comprising passing an unmixed synthesis gas stream (iv) through a power generation zone.   The chemical production zone is a methanol production zone, and a portion of the carbon dioxide is removed from the synthesis gas stream (i) or (iii) before passing through the methanol production zone of step (d). 10. The method of claim 9, further comprising providing a carbon dioxide concentration of 0.5 to 10 mole percent based on the total number of moles of gas in the synthesis gas stream (i) or (iii).   9. The method of claim 8, wherein the power generation zone comprises a combined cycle system, and the volume and / or composition of the mixed syngas stream varies depending on peak and off-peak power demands. The shifted syngas stream (i) has a molar ratio of hydrogen to carbon monoxide of 1: 1 to 20: 1; and
(D) generating steam in the water gas shift reaction zone by recovery of heat from the shifted syngas stream (i);
(E) combining the portion of the steam obtained in step (c) with the portion of one or more raw syngas streams before passing through the water gas shift reaction zone; and (f) the mixing The method of claim 1, further comprising passing the synthesis gas stream (iii) through a methanol or dimethyl ether production zone and passing the unmixed synthesis gas stream (iv) through a power generation zone.   In each of the synthesis gas streams (i) and (ii) obtained in step (b) or in each of the synthesis gas streams (iii) and (iv) obtained in step (e), a separate gas cooling zone, sulfur 13. The method of claim 12, further comprising passing through a removal zone, a separate acid gas removal zone including a carbon dioxide removal zone, or a combination thereof.   13. The method of claim 12, wherein the mixed synthesis gas stream (iii) is generated with a volume and / or composition that varies depending on peak and off-peak power demands. A method for producing variable amounts of power and methanol comprising:
(A) reacting an oxidant stream with coal or petroleum coke in a gasification zone comprising at least two gasifiers to produce at least two raw synthesis gas streams comprising carbon monoxide, hydrogen, carbon dioxide and a sulfur-containing compound; Generating;
(B) passing at least a portion of the raw syngas stream obtained in step (a) through a common water gas shift reaction zone to at least one shift syngas stream rich in hydrogen (i), Generating at least one non-shifted syngas stream (ii) comprising the remainder of the syngas stream;
(C) mixing the shifted syngas stream (i) and not more than 100 volume percent of the non-shifted syngas stream (ii) to produce at least one mixed syngas stream (iii) and the non-shifted syngas stream ( generating the remainder of ii);
(D) producing methanol by passing the mixed gas stream (iii) obtained in step (c) through a methanol production zone; and (e) the remainder of the non-shifted synthesis gas stream (ii) into the power production zone. Generating electricity through,
Generating the mixed synthesis gas stream with a volume and / or composition that varies depending on periods of peak and off-peak power demand in the power generation zone.   The process of claim 15, wherein the methanol production zone comprises a fixed bed or liquid slurry phase methanol reactor.   16. The method of claim 15, wherein the two or more gasifiers are sized to provide at least 90% of the maximum capacity fuel requirement of the power generation zone.   The method of claim 15, wherein 100 volume percent of the non-shifted syngas stream (ii) is mixed with the shifted syngas stream (i) during periods of off-peak power demand.

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